Standard Practice

Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas

(DG-ICDA)

This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281/228-6200).

Approved 2006-12-01

NACE International 1440 South Creek Dr.

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ISBN 1-57590-207-9

© 2006, NACE International

NACE SP0206-2006Item No. 21112

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Foreword This standard practice formalizes a methodology termed internal corrosion direct assessment for pipelines carrying normally dry natural gas (DG-ICDA)1,2,3 that can be used to help ensure pipeline integrity. The methodology is applicable to natural gas pipelines that normally carry dry gas, but may suffer from infrequent, short-term upsets of liquid water (or other electrolyte). This standard is intended for use by pipeline operators and others who manage pipeline integrity. The basis of DG-ICDA is a detailed examination of locations along a pipeline where water would first accumulate and provides information about the downstream condition of the pipeline. If the locations along a length of pipe most likely to accumulate water have not corroded, other downstream locations less likely to accumulate water may be considered free from corrosion. The presence of extensive corrosion found at many locations during the evaluation suggests that the transported gas was not normally dry, and this standard is not considered applicable. DG-ICDA methodology for natural gas systems is described in terms of a four-step process. The DG-ICDA method provides the greatest benefit for pipelines that cannot be in-line inspected; however, the method is not limited to unpiggable pipelines. Sample field data are provided in Appendix A (nonmandatory) to illustrate an example application of DG-ICDA. Appendix B (nonmandatory) provides example region definitions. This standard was prepared by Task Group (TG) 293 on Pipeline Direct Assessment Methodology. TG 293 is administered by Specific Technology Group (STG) 35 on Pipelines, Tanks, and Well Casings. This standard is issued by NACE International under the auspices of STG 35.

In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual, 4th ed., Paragraph 7.4.1.9. Shall and must are used to state mandatory requirements. The term should is used to state something good and is recommended but is not mandatory. The term may is used to state something considered optional.

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NACE International Standard Practice

Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)

Contents

1. General ............................................................................................................................... 1 2. Definitions ........................................................................................................................... 5 3. Pre-Assessment.................................................................................................................. 6 4. Indirect Inspection............................................................................................................... 9 5. Detailed Examinations ...................................................................................................... 11 6. Post Assessment .............................................................................................................. 13 7. DG-ICDA Records ............................................................................................................ 13 References .............................................................................................................................. 14 Bibliography............................................................................................................................. 15 Appendix A: Example DG-ICDA Application (Nonmandatory)............................................... 16 Appendix B: Example Region Definition (Nonmandatory) ..................................................... 21 Figure 1a: Dry Gas Internal Corrosion Direct Assessment Flow Chart ................................... 2 Figure 1b: Dry Gas Internal Corrosion Direct Assessment Flow Chart ................................... 3 Figure 1c: Dry Gas Internal Corrosion Direct Assessment Flow Chart.................................... 4 Figure A1: Example inclination and elevation profiles, with critical inclination

angles .............................................................................................................................. .18 Figure A2: Example inclination profile, gas flowing south to north (first 6.4

km [4 miles])...................................................................................................................... 19 Figure A3: Example inclination profile, gas flowing north to south (first 6.2

km [3.9 miles])................................................................................................................... 20 Figure B1: Illustration of ICDA Region Definitions ................................................................. 21 Table 1: Essential Data for Use of DG-ICDA Methodology ..................................................... 7 Table A1: Example Conditions................................................................................................ 17 Table A2: Example—Inspection Results................................................................................ 19

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Section 1: General

1.1 Introduction

1.1.1 This standard covers the NACE internal corrosion direct assessment (ICDA) process for normally dry natural gas pipeline systems. This standard is intended to serve as a guide for applying the NACE DG-ICDA process on natural gas pipeline systems that meet the feasibility requirements of Paragraph 3.3 of this standard. 1.1.2 The primary purposes of the DG-ICDA method are (1) to enhance the assessment of internal corrosion in natural gas pipelines, and (2) to ensure pipeline integrity. 1.1.3 DG-ICDA was developed for natural gas pipelines that normally carry dry gas, but may suffer from infrequent short-term upsets of water. Because of this, DG-ICDA is not applicable to wet gathering and producing pipelines. 1.1.4 One benefit of the DG-ICDA approach is that an assessment can be performed on a pipe segment for which alternative methods (e.g., in-line inspection (ILI), hydrostatic testing, etc.) may not be practical. 1.1.5 The basis of DG-ICDA for gas lines is a detailed examination of locations along a pipeline where water or other electrolyte first accumulates, allowing inferences to be made about the integrity of the remaining downstream length of pipe. 1.1.6 If the locations along a length of pipe that are most likely to accumulate water have not corroded, other locations less likely to accumulate water are unlikely to have suffered corrosion when operating under the same conditions. 1.1.7 Identifying areas in which internal corrosion (or the potential for future internal corrosion) exists, and conversely, where internal corrosion is unlikely, may also be incorporated into corrosion integrity and risk management plans. 1.1.8 In the process of applying DG-ICDA, other pipeline integrity threats, such as external corrosion, mechanical damage, stress corrosion cracking (SCC), etc., may be detected. When such threats are detected, additional assessments or inspections must be performed. The pipeline operator should utilize appropriate methods to address risks other than internal corrosion, such as those described in NACE

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standards, ASME(1) B31.8,4 API(2) 1160,5 ANSI(3)/API 579,6 and BS(4) 7910,7 international standards, and other documents. 1.1.9 The DG-ICDA methodology assesses the likelihood of internal corrosion and includes existing methods of examination available to a pipeline operator to determine whether internal corrosion is actually present, or may occur. 1.1.10 DG-ICDA uses flow modeling results and provides a framework to utilize those methods. 1.1.11 DG-ICDA has limitations, and not all pipelines can be successfully assessed with DG-ICDA. These limitations are identified in the pre-assessment step. For accurate and correct application of this standard, it shall be used in its entirety. Using or referring to only specific paragraphs or sections can lead to misinterpretation or misapplication of the recommendations and practices contained herein. 1.1.12 This standard does not designate practices for every specific situation because of the complexity of internal conditions that may be present in various pipeline systems. 1.1.13 This standard does not address specific remedial actions that may be taken when corrosion is found; however, the reader is referred to ASME B31.84 and other relevant documents for guidance.

1.1.14 The provisions of this standard shall be applied by or under the direction of competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics, acquired by education and related practical experience, are qualified to engage in the practice of corrosion control and risk assessment on pipeline systems. Such persons may be (1) registered professional engineers, (2) recognized as corrosion specialists by organizations such as NACE, or (3) professionals (i.e., engineers or technicians) with professional experience including detection/mitigation of internal corrosion and evaluation of internal corrosion on pipelines.

1.2 Four-Step Process

1.2.1 DG-ICDA requires the integration of data from multiple field examinations and internal pipe surface evaluations, including the pipeline’s physical characteristics and operating history.

(1) ASME International (ASME), Three Park Ave., New York, NY, 10016-5990. (2) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005. (3) American National Standards Institute (ANSI), 11 W. 42nd St., New York, NY 10036. (4) British Standards Institute (BSI), British Standards House, 389 Chiswick High Rd., London W4 4AL, United Kingdom.

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A flow chart that illustrates the components of each step is shown in Figure 1.

Ste

p 1.

Pre

-ass

essm

ent

Ste

p 2.

Indi

rect

Insp

ectio

n

Internal Corrosion Threat

Data Collection 3.2

Sufficient Data? 3.2.1

Can data be obtained or assumed?

3.2.4

Feasibility Established?

3.3

Define Each DG-ICDA Region

3.4

DG-ICDA not applicable, back

to determine assessment

method.

Input on Essential Data 3.2.2, Table 1

Select Indirect Inspection Tools

4.2, 4.3

Define Critical Inclination Angles for

Each Region 4.2

Determine Inclination Profile for Each Region

4.3

Select Sites for Detailed Examination

4.4 and 4.5

Compare and Analyze Results

4.6

To DETAILED EXAMINATIONS

Feedback 7.5.1

Input on Tool Selection for Flow

Modeling and Inclination Profile

Calculations

Accept

Reject

Yes

No No

No

Yes

Yes

Input on Region Identification

Criteria 3.4.1

FIGURE 1a: Dry Gas Internal Corrosion Direct Assessment Flow Chart

Numbers refer to paragraph numbers in this standard.

Reject

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FIGURE 1b: Dry Gas Internal Corrosion Direct Assessment Flow Chart Numbers refer to paragraph numbers in this standard.

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FIGURE 1c: Dry Gas Internal Corrosion Direct Assessment Flow Chart

Numbers refer to paragraph numbers in this standard.

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1.2.2 DG-ICDA includes the following four steps:

1.2.2.1 Pre-assessment collects essential historic and present operating data about the pipeline, determines whether DG-ICDA is feasible, and then defines ICDA regions. The types of data to be collected are typically available in design and construction records, operating and maintenance histories, alignment sheets, corrosion survey records, gas and liquid analysis reports, and inspection reports from prior integrity evaluations or maintenance actions. 1.2.2.2 Indirect inspection covers multiphase flow predictions, developing a pipeline elevation profile,

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and identifying sites where internal corrosion may be present. 1.2.2.3 Detailed examination includes performing excavations and conducting detailed examinations of the pipe to determine whether metal loss from internal corrosion has occurred. 1.2.2.4 Post assessment covers analysis of data collected from the previous three steps to assess the effectiveness of the DG-ICDA process and determine reassessment intervals.

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Section 2: Definitions

Anomalies: See Indication. Cleaning Pig: A device inserted in a pipeline for cleaning solids or displacing liquids from within a pipeline. A spheroid implement used to displace liquid hydrocarbons from natural gas pipelines. Corrosion: The deterioration of a material, usually a metal, that results from a reaction with its environment. Critical Inclination Angle: Angle determined by DG-ICDA flow modeling; the lowest angle at which liquid carryover is not expected to occur under stratified flow conditions. DG-ICDA Region: A continuous length of pipe (including weld joints) uninterrupted by any significant change in water or flow characteristics that includes similar physical characteristics or operating history. DG-ICDA Subregion: A continuous length of pipe (including weld joints) contained in a DG-ICDA region, defined as the pipe length between two inclination angles at which corrosion is found or the start of the region and the first inclination angle. Defined Length: Any length of pipe until a new inlet introduces the possibility of water entering the pipeline. Direct Assessment: A structured process for pipeline operators to assess the integrity of pipelines. Detailed Examination: Examination of the pipe wall at a specific location to determine whether metal loss from internal corrosion has occurred. This may be performed using visual, ultrasonic, radiographic, or other means. Dry Gas: A gas above its dew point and without condensed liquids. Dry Gas Internal Corrosion Direct Assessment (DG-ICDA): The internal corrosion direct assessment process as

defined in this standard applicable to normally dry gas systems. Future documents may address ICDA for wet gas and liquid hydrogen systems. Electrolyte: A chemical substance containing ions that migrate in an electric field. External Corrosion Direct Assessment (ECDA): A four-step process that combines pre-assessment, indirect inspections, direct examinations, and post assessment to evaluate the impact of corrosion occurring on the outside wall of a pipe upon the integrity of a pipeline. Fluid: A substance that does not permanently resist distortion. Both liquids and gases are fluids. Gathering System: Pipeline and related facilities to collect and move produced gas progressively starting from individual wells to a trunk, common, or main line. Produced gas may not meet gas quality specifications typical of gas transmission systems. Hydrostatic Testing: Testing of sections of a pipeline by filling the pipeline with water and pressurizing it until the nominal hoop stresses in the pipe reach a specified value. Inclination Angle: An angle resulting from a change in elevation between two points on a pipeline, in degrees. Indication: Any measured deviation from the norm. Indirect Inspection: Use of tools to examine a pipeline indirectly. For DG-ICDA, it consists of calculating and comparing flow modeling results with an inclination profile. In-Line Inspection (ILI): The inspection of a pipeline from the interior of the pipe using an ILI tool. The tools used to conduct ILI are known as pigs, smart pigs, or intelligent pigs.

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Liquid: A substance that tends to maintain a fixed volume but not a fixed shape. Liquid Holdup: Accumulation of liquid (i.e., input liquid volume is greater than output liquid volume). Low Point: A location having higher elevations immediately adjacent upstream and downstream; any liquid is expected to preferentially collect at such locations during stagnant flow conditions. Natural Gas: Primarily methane as produced from natural sources. Pigging: See In-Line Inspection or Cleaning Pig. Potential Liquid Holdup Location: Pipeline locations and features, such as sags, drips, inclines, valves, manifolds, dead legs, and traps, where liquids can accumulate. Region: See DG-ICDA Region.

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Segment: A portion of a pipeline that is (to be) assessed using DG-ICDA. A segment may consist of one or more ICDA regions. Stratified Flow: A multiphase-flow regime in which fluids are separated into layers, with lighter fluids flowing above heavier (i.e., higher density) fluids. Superficial Gas Velocity: The volumetric flow rate of gas (at system temperature and pressure) divided by the cross-sectional area of the pipe. Tariff Quality Gas: Natural gas transported by pipeline that meets certain compositional requirements, generally as related to the sale of natural gas. Tariff requirements differ among companies, but usually include specifications for water vapor (H2O), hydrogen sulfide (H2S), total sulfur (S), carbon dioxide (CO2), heating value, and temperature.

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Section 3: Pre-Assessment

3.1 Introduction

3.1.1 The objectives of the pre-assessment step are to (1) determine whether DG-ICDA is feasible for the pipeline being evaluated, and (2) to identify DG-ICDA regions. 3.1.2 The pre-assessment step requires data collection, integration, and analyses. The pre-assessment step must be performed in a comprehensive and thorough fashion. 3.1.3 The pre-assessment step includes the following activities:

3.1.3.1 Data collection; 3.1.3.2 Assessment of DG-ICDA feasibility; and 3.1.3.3 Identification of DG-ICDA regions.

3.2 Data Collection

3.2.1 The pipeline operator shall collect historical (i.e., over the life of the pipe) and current data, along with physical information for each segment to be evaluated.

3.2.1.1 The pipeline operator shall define minimum data requirements based on the history and condition of the pipeline segment. In addition, the pipeline operator shall identify data elements that are critical to the success of the DG-ICDA process (see Table 1 for essential information).

3.2.1.2 All parameters that have an impact on DG-ICDA region definition (see Paragraph 3.4) shall be considered for initial DG-ICDA process applications on a pipeline segment. 3.2.1.3 Accurate and complete elevation profile, flow rate data, and pressure history are essential to predicting the locations of liquid holdup.

3.2.2 At a minimum, the pipeline operator shall collect essential data from the following categories, as shown in Table 1. In addition, a pipeline operator may determine that items not included in Table 1 are necessary.

3.2.2.1 Operating history; 3.2.2.2 Defined length; 3.2.2.3 Elevation profile;

3.2.2.4 Features with inclination; 3.2.2.5 Diameter and wall thickness; 3.2.2.6 Pressure, typical operating and maximum range; 3.2.2.7 Maximum and minimum flow rates over the range of operating pressures; 3.2.2.8 Temperature, typical range of operations; 3.2.2.9 Water vapor content;

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3.2.2.10 Types and locations of inputs/outputs; 3.2.2.11 Corrosion inhibitor(s); 3.2.2.12 Upsets; 3.2.2.13 Type of dehydration; 3.2.2.14 Hydrostatic test information; 3.2.2.15 Repair/maintenance data;

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3.2.2.16 Location of leaks/failures; 3.2.2.17 Gas quality; 3.2.2.18 Corrosion monitoring; 3.2.2.19 Existence and location(s) of any flow coatings; and 3.2.2.20 Other internal corrosion data.

Table 1: Essential Data for Use of DG-ICDA Methodology

CATEGORY DATA TO COLLECT Operating history Change in gas flow direction, type of service, removed taps, year of installation, etc.

Has the line ever been used previously for crude oil or other liquid products? Defined length Length between inputs/outputs. Elevation profile Topographical data (e.g., USGS(A) data), including consideration of a pipeline depth

of cover. Take care in instrument selection that sufficient accuracy and precision may be achieved.

Features with inclination Roads, rivers, drains, valves, drips, etc. Diameter and wall thickness Nominal pipe diameter and wall thickness. Pressure Typical minimum and maximum operating pressures. Flow rate Flow rates—maximum and minimum flow rates at minimum and maximum operating

pressures for all inlets and outlets. Significant periods of low/no flow. Temperature For example, ambient soil temperature up to 54°C (130°F) at compressor discharge2

unless a special environment (e.g., river crossing, aerial pipeline) exists. Water vapor Information about water vapor dew point. Inputs/outputs Must identify all locations of current and historic inputs and outputs to the pipeline. Corrosion inhibitor Information about injection, chemical type, and dose. Upsets Frequency, nature of upset (intermittent or chronic), volume if known, and nature of

liquid. Type of dehydration Is dehydration carried out using glycols (yes/no)? Hydrotest information Past presence of water, hydrotest water quality data. Repair/maintenance data Presence of solids, anomalies; pipe section repair and replacement; prior

inspections; nondestructive examination (NDE) data. Any cleaning pig locations, frequencies, and dates. Analytical data of all removed sludge, liquids when cleaning pigs were employed or from liquid separators, hydrators, etc., and the analysis performed to determine the chemical properties and corrosiveness, including the presence of bacteria, of the removed products.

Leaks/failures Locations and nature of leaks/failures. Gas quality Gas and liquid analyses, and any bacteria testing results for the pipeline and on

shipper and delivery laterals. Relationship of gas analyses to pipe location. Corrosion monitoring Corrosion monitoring data including type of monitoring (e.g., coupons, electric

resistance [ER]/linear polarization resistance [LPR] probes), dates and relationship of monitoring to pipe location, corrosion rate recorded/calculated, and accuracy of data (e.g., NACE Publication 3T1998). Any available nondestructive inspection results.

Flow coatings Existence and location(s) of internal coatings. Other internal corrosion data As defined by the pipeline operator.

(A) U.S. Geological Survey (USGS), 12201 Sunrise Valley Dr., Reston, VA 20192.

3.2.3 The data collected in the pre-assessment step often include the same data typically considered in an overall pipeline risk (threat) assessment. Depending on the pipeline operator’s integrity management plan and its implementation, the operator may conduct the

pre-assessment step in conjunction with an external corrosion direct assessment (ECDA) or other risk-assessment effort.

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3.2.4 When data for a particular category are not available, conservative assumptions shall be used based on the operator’s experience and information about similar systems. The basis for these assumptions shall be documented.

3.2.5 In the event that the pipeline operator determines that sufficient data are not available or cannot be collected for some DG-ICDA regions comprising a segment to support the pre-assessment step, DG-ICDA shall not be used for those DG-ICDA regions until the appropriate data can be obtained.

3.3 DG-ICDA Feasibility Assessment The pipeline operator shall examine the data collected in Paragraph 3.2 to determine whether conditions that would preclude this DG-ICDA application or for which indirect inspection tools cannot be used exist. The following conditions are required to apply this DG-ICDA standard:

3.3.1 The pipeline should not normally contain any liquids, including glycols;

3.3.2 The pipeline should not have been previously converted from a service for which DG-ICDA is not applicable (e.g., crude oil or products) unless it is demonstrated either that internal corrosion did not occur in the previous service or that previous damage has been separately assessed.

3.3.3 The pipeline must not have an internal coating that provides corrosion protection. For pipelines with discontinuous protective coating, indirect examinations must be performed at nonprotective locations. 3.3.4 If history indicates internal corrosion on the top of the pipeline from wet gas (i.e., from condensing water), this standard is not applicable because DG-ICDA is not suitable for detecting top-of-the-line corrosion. 3.3.5 Pigging affects areas where liquids could collect, which directly affects the distribution of internal corrosion in a way that is not predicted by DG-ICDA. Thus, DG-ICDA may not be appropriate for pipelines that have been routinely pigged. The operator must provide technical justification when DG-ICDA is applied to a pipeline that has any history of use of cleaning pigs. 3.3.6 The use of corrosion inhibitor may preclude application of DG-ICDA because the effectiveness of the inhibitor might not be uniform along the pipeline length. Data from Table 1 should be considered.

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3.3.7 Pipelines that contain accumulations of solids, sludge, biofilm/biomass, or scale should not be assessed using this DG-ICDA standard, unless the influence of those materials has been carefully evaluated. Based on information collected as part of the pre-assessment (see Step 3.2 in Figure 1a), operators must determine whether accumulations of solids are significant enough to influence the validity of the DG-ICDA results through any of the mechanisms described below. The presence of solids, sludge, and scale may affect the validity of this DG-ICDA process by: • Increasing corrosion through retaining water inside

a porous matrix or under a solid layer; • Increasing corrosion by attracting water through

hygroscopic properties or deliquescence; • Increasing corrosion through the formation of a

concentration cell (i.e., under-deposit corrosion); • Decreasing corrosion through the formation of a

protective layer; and • Changing corrosion rates due to the influence of

bacteria. 3.3.8 Material Properties DG-ICDA assumes uniform material properties along a pipeline segment. Consideration for differences such as weld type, geometry, and material defects must be made. Special consideration should be given for possible selective-seam corrosion on ER welded pipe (where the seam is oriented at pipe bottom).

3.4 Identification of DG-ICDA Regions The pipeline operator shall define DG-ICDA regions from the data collected in the pre-assessment step. 3.4.1 A DG-ICDA region is a portion of pipeline with a defined length. A defined length is any length of pipe until a new input introduces the possibility of water entering the pipeline. 3.4.2 In defining DG-ICDA regions, the operator shall consider process changes such as temperature and pressure. Such changes over the segment length either:

3.4.2.1 Should be considered as separate DG-ICDA regions, or

3.4.2.2 The critical inclination angle (see Section 4) at any point within a region must be based on the local pressure and temperature at that point.

3.4.3 Input changes also include new direction of gas flow. In the case of bidirectional flow history, DG-ICDA regions shall be identified for each flow direction, and each flow direction shall be treated separately.

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Section 4: Indirect Inspection

4.1 Introduction The objective of the DG-ICDA indirect inspection is to use flow modeling results to predict the locations most likely to have suffered internal corrosion within each DG-ICDA region. The DG-ICDA indirect inspection step relies on the ability to identify locations most likely to accumulate water and is applicable to pipelines in which stratified flow is the primary liquid transport mechanism. The DG-ICDA indirect inspection step shall include each of the following activities, for each DG-ICDA region:

4.1.1 Performing multiphase flow calculations using collected data to determine the critical inclination angle of liquid holdup; 4.1.2 Producing a pipeline inclination profile; and 4.1.3 Identifying sites where internal corrosion may be present by integrating the flow calculation results with the pipeline inclination profile.

4.2 Flow Modeling Calculations

4.2.1 The operator shall predict critical parameters for water accumulation using flow modeling calculations for each identified DG-ICDA region. Any multi-phase flow modeling approach valid for small liquid volumes is acceptable. In principle, the simplified flow modeling approach included in this standard1,2,3 (Paragraph 4.2.2) may be applied to all systems with stratified flow. Although expected to be valid for a wider range of conditions (and supporting calculations may be performed to demonstrate this or other technical support may be documented), supporting calculations exist within the following bounds:

4.2.1.1 Nominal pipe diameter is between 0.1 and 1.2 m (4 and 48 in.); 4.2.1.2 Pressures less than 7.6 MPa (1,100 psi).

4.2.2 A simple method to predict the critical inclination angle (θ) utilizes a correlation obtained between sin (θ) and the ratio of gas inertia force to liquid gravitational force, which combines results of simulations in Equation (1),3 and is similar to other expressions.1,2

1.091

id

2g

gl

g

dg

V

ρρρ

0.675 arcsin θ ⎟⎟

⎠

⎞

××⎜

⎜⎝

⎛

−= (1)

Where:

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θ = critical inclination angle (degrees); ρl = liquid density; ρg = gas density (determined by total pressure and temperature); g = acceleration due to gravity; did = internal diameter; and Vg = superficial gas velocity The units of gas and liquid density must be the same, and the units for velocity, gravitational constant, and diameter must be consistent. The operator shall consider a compressibility factor, Z, in these calculations, as well as any non-ideal behavior in gas density determination.9,10 The following expression, Equation (2), represents this factor:

nRT

PV=Z (2)

Where: Z = compressibility factor (dimensionless) P = pressure V= volume n = moles R = the gas constant T = absolute temperature Values for Z in various conditions, and the guidance on non-ideal gas equations, can be found in basic reference texts.9,10 Van der Waal’s equation (Equation 3) is used to simulate nonlinear behavior of non-ideal (i.e., real) gases.

RTnb))(VV

an(P

2

2

=−+ (3)

Where “a” and “b” are critical constants of the gases transported.11,12 Superficial velocity (Vg) and critical inclination angle calculated using compressibility factor (Z) and Equation (3) may be different.11,12

4.2.2.1 For the DG-ICDA flow calculations, the operator shall use the highest critical inclination angle resulting from the combination of process parameters (i.e., pressure, temperature, and superficial gas velocity) to which the pipeline has been exposed over its operational history. If the history of flow conditions is well-documented, the selection of the critical inclination angle can be optimized.

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4.2.3 In the flow method shown in Paragraph 4.2.2, all values should be known except θ, which is determined from Equation (1).

4.2.4 The critical inclination angle is not necessarily constant within a DG-ICDA region (e.g., changes in internal diameter) and is usually plotted against distance.

4.3 Inclination Profile Calculation

4.3.1 The operator shall calculate the inclination profile of the pipeline, or change in elevation over the defined length. The accuracy of the inclination profile is critical to the success of DG-ICDA, and the accuracy of methods to measure the profile must be documented (including consideration of pipeline depth-of-cover). 4.3.2 The inclination profile shall be composed of multiple sets of data points for each DG-ICDA region examined and is calculated by Equation (4):

⎟⎟⎠

⎞⎜⎜⎝

⎛)∆(distance

n)∆(elevatio arcsin=θ (4)

4.3.3 Elevation measurements must be taken at intervals that capture all relevant changes in the inclination profile. The minimum interval depends on the specific pipeline being evaluated, the terrain, and other features. Uncertainty in the inclination profile must be estimated based on the accuracy of elevation data. 4.3.4 The operator shall document the procedure for collecting the elevation data, the elevation data obtained, the assumptions made in this process, the method of determining uncertainty of the inclination profile, and this uncertainty.

4.4 Site Selection—General

4.4.1 Sites at which internal corrosion may be present shall be determined by integrating the flow modeling results with the pipeline inclination profile. Selection should include consideration of inclination angles at road crossings, rivers, drainage ditches, and other locations. 4.4.2 The pipeline operator shall identify possible internal corrosion sites where liquid holdup could occur based on the comparison of the critical inclination angle calculations with the elevation profile results.

4.4.3 If there has been bidirectional flow through the pipeline, inclinations for the opposite direction shall be

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considered as separate DG-ICDA regions, and each direction treated separately.

4.4.4 Water accumulation is expected to occur on (or at the onset of) uphill sections of pipe in the direction of flow.

4.5 Site Selection—Specific

4.5.1 If collected data include information about the period of time a pipeline experienced velocity ranges, the operator should evaluate the significance of the ranges using flow modeling or equivalent. 4.5.2 For each DG-ICDA region, the operator shall find the first pipe inclination downstream from the beginning of the region greater than the largest critical inclination angle determined by the range of operating conditions and the flow modeling results.

4.5.2.1 If all inclinations have angles smaller than critical, the operator shall choose the angle of greatest inclination within the DG-ICDA region.

4.5.3 For a short elevation change associated with a feature (e.g., a road crossing), water accumulation commonly occurs on the short uphill segment, indicating a limited section of pipe to examine or inspect.

4.5.4 When a long upslope exists—such as that found where a pipeline rises up a hill or mountain—identification of the liquid holdup location within the section of pipe may be more difficult, and the liquid holdup location can occur over a longer area. 4.5.5 In some cases, drips or other facility components that accumulate liquid may serve as detailed examination points. If they cannot be used as examination points, they must be assessed separately. The components may be used as DG-ICDA examination points if it can be demonstrated that they:

4.5.5.1 Have a design operation and maintenance that effectively traps liquids; and 4.5.5.2 Have a corrosion environment that either represents or is more severe than the pipeline.

4.6 Comparison and Analysis The results of the indirect inspection shall be evaluated. If necessary, additional data (see Paragraph 3.2) shall be collected and the analysis repeated.

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Section 5: Detailed Examinations

5.1 Introduction

5.1.1 The objectives of the DG-ICDA detailed examination are (1) to determine whether internal corrosion exists at locations selected in the previous step, and (2) to use the findings to assess the overall condition of the DG-ICDA region. 5.1.2 The detailed examination step focuses examination efforts on locations and features most likely to experience internal corrosion. 5.1.3 Excavation and subsequent inspection sufficient to identify and characterize internal corrosion features in the pipe must be used. 5.1.4 Procedures for nondestructive inspection techniques (NDT) and action as a result of identifying defects during the inspection are not included in the scope of this standard. The operator must follow the appropriate guidelines located in related NACE and ASME International standards for evaluating each site for and responding to the presence and extent of corrosion. 5.1.5 During the detailed examination step, defects other than internal corrosion may be found. While defects such as external corrosion, mechanical damage, and SCC may be found, alternative methods must be considered for assessing the impact of such defect types. 5.1.6 Alternative methods are given in ASME B31.8 Update,3 ASME B31.8,4 API 1160,5 ANSI/API 579,6 BS 7910,7 NACE standards, international standards, and other documents. 5.1.7 The priority in which excavations and detailed examinations are made shall be determined by a comparison of flow modeling results with the pipe inclination profile.

5.1.8 An alternative to the deterministic detailed examination process as described in Figures 1a, 1b, and 1c is to optimize the number of excavations required for DG-ICDA assessment by engineering analysis (including probabilistic methods). The use of an alternative approach shall be technically justified and the methodology and assumptions documented.

5.2 Performing the Detailed Examination Process Selection and examination of sites for detailed examination shall be based on the detailed examination process diagram as shown in Figures 1a, 1b, and 1c. Any deviation from this process must be technically justified by the operator and the reasons documented.

nternational

5.2.1 In summary, locations with inclination greater than the critical angle must be examined moving downstream from the beginning of a region. Two consecutive locations must be found free from internal corrosion to complete the assessment. In addition, a third examination at the next location with inclination greater than the critical angle serves as validation of the assessment.

5.2.1.1 If no angles greater than critical exist, the largest must be examined. If corrosion is found, the next largest downstream location is selected. If no corrosion is found, one additional (next largest) location serves as validation. 5.2.1.2 To account for previous low flow (i.e., if steady-state flow cannot be documented), at least two inspections must be performed in subregion ‘n’ = 0, which is defined between the beginning of the DG-ICDA region and the first site examined. If there is only one location with inclination upstream from the first site inspected, only one site must be inspected in the subregion. If there are no locations with inclinations in the subregion, no sites need to be inspected in that subregion. 5.2.1.3 If the pipeline has experienced bidirectional flow, the effect(s) of changing flow direction on corrosion distribution at selected sites shall be considered. This is in addition to treating the reverse directions as separate regions.

5.2.2 One of the following criteria shall be used for measurements to determine the presence of significant internal corrosion. These criteria are the basis for determining the number of required detailed examinations.

5.2.2.1 Internal corrosion metal loss is considered significant if the wall thickness is less than minimum specified nominal (compensation for metal loss from external corrosion can be made). For example, pipelines operating at less than 72% of the specified minimum yield strength (SMYS) would have a criterion of 10% (based on wall tolerance13) to indicate the presence of internal corrosion. In this case, additional DG-ICDA excavation sites are triggered when the wall thickness is less than 90% of specified thickness. 5.2.2.2 A pipeline-specific analysis may be performed to develop criteria for significant internal corrosion. The analysis might include consideration of previous metal loss and years of pipeline service.

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5.2.2.3 Other technical criteria for significant corrosion may be used with documented technical justification.

5.2.3 If the pipeline has been subjected to bidirectional flow, the detailed examination process must be completed for both directions; internal corrosion may then be concluded unlikely in the downstream length bounded by regions for each direction. 5.2.4 Operators may perform additional validation examinations at their discretion on regions for which the detailed examination process has been completed. 5.2.5 When the detailed examination process identifies the existence of extensive severe internal corrosion, the operator shall return to pre-assessment, because the applicability of DG-ICDA is in question.

5.2.6 When performing the detailed examination step, the operator shall conduct detailed, accurate measurements of the wall thickness and determine the axial length of any wall loss indications present. The length of the pipeline affected by water accumulation may be large in some situations, and care should be taken in selecting the proper NDE technique. Remaining wall thickness values must be identified. 5.2.7 Nondestructive testing methods used to determine the remaining wall of the pipe in corroded areas shall be performed in accordance with qualified written procedures and applicable NACE standards by individuals qualified by training and experience. 5.2.8 The pipeline operator shall evaluate or calculate the remaining strength of locations where corrosion is found. Example methods for calculating the remaining strength include ASME B31G,14 RSTRENG,15,16 and DnV RP-F101.17 5.2.9 The inspection procedures, detailed wall thickness data, and strength calculations must be retained with the DG-ICDA records for the pipeline.

5.3 Other Facility Components

5.3.1 In some cases, drips or other facility components may serve as DG-ICDA examination points (see Paragraph 4.5.5). 5.3.2 If the fixture geometry restricts evaporation, it is possible for corrosion to be more severe inside the fixture even when located downstream from a mainline inclination with greater than critical angle. Therefore, the pipeline operator shall examine at least one fixture

12

of similar design where water can be trapped directly downstream from a pipe inclination with angle greater than critical. The decision to forgo examinations of further downstream fixtures must be justified and documented.

5.4 Excavation and Inspection

5.4.1 The pipeline operator must use supplementary standards to perform corrosion detection and mitigation because these are not included in the scope of the DG-ICDA standard. However, improvements for real-time monitoring and future site accessibility for DG-ICDA, to be installed concurrently with excavations/inspections, are recommended. 5.4.2 Once a site has been exposed, the operator may install a corrosion monitoring device (e.g., coupon, electronic probe, ultrasonic sensor, or electrical resistance matrix, etc.) that may allow an operator to determine inspection intervals and benefit from monitoring in the locations most susceptible to internal corrosion.8

5.4.2.1 Coupons installed at arbitrary locations (e.g., end of pipeline) are not expected to represent a pipeline with internal corrosion that varies with location.

5.4.3 ILI tool (or other assessment) results for an upstream portion of pipe within a region may provide information that can be used to help assess the downstream condition of the pipeline where a pig cannot be run.

5.4.3.1 Because DG-ICDA predicts that corrosion is more likely upstream than downstream, integrity verification of the upstream locations allows a conclusion to be drawn about downstream locations. 5.4.3.2 Use of ILI data for detailed assessment must be supplemented by excavation and inspection consistent with sites identified in the indirect inspection step of DG-ICDA.

5.4.4 If the operator utilizing DG-ICDA determines that the locations most susceptible to internal corrosion due to the presence of water accumulation are free from metal loss, the integrity of a large portion of pipeline mileage has been assured relative to this corrosion threat, and resources can be focused on pipelines on which internal corrosion is determined to be more likely.

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Section 6: Post Assessment

6.1 Introduction

6.1.1 The objectives of the post-assessment step are to assess the effectiveness of DG-ICDA and to determine reassessment intervals.

6.2 Assessment of DG-ICDA Effectiveness

6.2.1 Effectiveness of the DG-ICDA process is determined by the correlation between detected corrosion and the DG-ICDA predicted locations.

6.2.1.1 Operators must evaluate the effectiveness of DG-ICDA, and the process shall be documented. 6.2.1.2 Improvements as a result of this assessment shall be incorporated into future applications of DG-ICDA.

6.2.2 If extensive corrosion is found throughout the pipeline, or corrosion is found at the top of the pipe, the assumption of normally dry gas shall be reevaluated.

6.3 Determination of Reassessment Intervals

6.3.1 DG-ICDA reassessment intervals may be determined using one or more of the following methods:

rnational

6.3.1.1 Reexamine site at a prescribed frequency to determine or assess growth rate (i.e., monitor site for corrosion growth on the actual pipe). 6.3.1.2 Install one or more corrosion monitoring devices at sites of predicted liquid accumulation based on flow modeling results or at other representative locations. 6.3.1.3 Apply a corrosion rate model based on operating conditions, gas quality, liquid composition, and other key factors. 6.3.1.4 Perform laboratory testing on fluids based on operating conditions, gas quality, liquid composition, and other key factors to determine corrosiveness.

6.3.2 The selected method(s) of reassessment interval determination must be technically justified and validated by the operator. 6.3.3 The distribution and uncertainty of predicted corrosion rates must be considered. 6.3.4 If it can be demonstrated that the introduction of corrosive electrolytes is unlikely, the threat of future internal corrosion can be removed.

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Section 7: DG-ICDA Records

7.1 Introduction

7.1.1 This section describes DG-ICDA records that document—in a clear, concise, and workable manner—data that are pertinent to pre-assessment, indirect inspection, detailed examination, and post assessment. All decisions and supporting assessments must be documented. The records required by the standard should be kept for the life of the pipeline.

7.2 Pre-Assessment Documentation

7.2.1 All pre-assessment step actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.2.1.1 Data elements collected for the segment to be evaluated, in accordance with Table 1.

7.2.1.2 Methods and procedures used to integrate the data collected to determine when indirect inspection tools can and cannot be used. 7.2.1.3 Characteristics and boundaries of DG-ICDA regions.

7.3 Indirect Inspection

7.3.1 All indirect inspection actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.3.1.1 Geographically referenced locations of the beginning and ending point of each DG-ICDA region and each fixed point used for determining the location of each measurement. 7.3.1.2 Procedures for determining accuracy of inclination profiles.

7.4 Detailed Examinations

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7.4.1 All detailed examination actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.4.1.1 Data collected before and after excavation.

7.4.1.1.1 Measured metal loss corrosion geometries. 7.4.1.1.2 Data used to identify other areas that may be susceptible to corrosion. 7.4.1.1.3 Data used to estimate corrosion growth rates.

7.4.1.2 Planned mitigation activities. 7.4.1.3 Descriptions of and reasons for any selections of additional sites or reprioritizations.

7.5 Post Assessment

7.5.1 All post-assessment actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.5.1.1 Remaining life calculation results.

14

7.5.1.1.1 Maximum remaining flaw sizedeterminations. 7.5.1.1.2 Corrosion growth ratedeterminations. 7.5.1.1.3 Method of estimating remaining life. 7.5.1.1.4 Results of remaining strengthcalculations.

7.5.1.2 Reassessment intervals, includingtechnical justification and operator’s validation ofselected method of reassessment; and anyscheduled activities. 7.5.1.3 Criteria used to assess DG-ICDAeffectiveness and results from assessments.

7.5.1.3.1 Criteria and metrics. 7.5.1.3.2 Data from periodic assessments.

7.5.1.4 Monitoring Records 7.5.1.5 Feedback

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References

1. O.C. Moghissi, L. Norris, P. Dusek, B. Cookingham, “Internal Corrosion Direct Assessment of Gas Transmission Pipelines,” CORROSION/2002, paper no. 87 (Houston, TX: NACE, 2002). 2. O.C. Moghissi, L. Norris, P. Dusek, B. Cookingham, N. Sridhar, “Internal Corrosion Direct Assessment of Gas Transmission Pipelines–Methodology,” GTI Final Report GRI-02/0057 (Des Plaines, IL: GTI,(5) 2002). 3. ANSI/ASME B31.8 Update (latest revision), “Gas Transmission and Distribution Piping Systems” (New York, NY: ASME). 4. ANSI/ASME B31.8 (latest revision), “Gas Transmission and Distribution Piping Systems” (New York, NY: ASME). 5. API 1160 (latest revision), “Managing System Integrity for Hazardous Liquid Pipelines” (Washington, DC: API). 6. ANSI/API 579 (latest revision), “Fitness for Service” (Washington, DC: API) 7. BS 7910 (latest revision), “Guide on methods for assessing the acceptability of flaws in metallic structures” (London, England: BSI).

8. NACE Publication 3T199 (latest revision), “Techniques for Monitoring Corrosion and Related Parameters in Field Applications” (Houston, TX: NACE). 9. J. O’Connell, B. Poling, J. Prausnitz, The Properties of Gases and Liquids, 5th ed. (New York, NY: McGraw-Hill, 2001). 10. R. Perry, D. Green, Perry’s Chemical Engineers’ Handbook, 7th ed. (New York, NY: McGraw-Hill, 1997). 11. S. Papavinasam, A. Dorion, G. Shen, R.W. Revie, “Prediction of Inhibitor Behaviour in the Field from Data in the Laboratory,” CORROSION/2004, paper no. 04622 (Houston, TX: NACE International, 2004). 12. S. Papavinasam, A. Dorion, R.W. Revie, “Integriy Management of New Pipelines: Internal Corrosion Control,” CORROSION/2006, paper no. 06187 (Houston, TX: NACE International, 2006). 13. API Specification 5L (latest revision), “Specification for Line Pipe” (Washington, DC: API).

___________________________ (5) Gas Technology Institute (GTI), 1700 S. Mount Prospect Rd., Des Plaines, IL 60018.

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14. ANSI/ASME B31G (latest revision), “Manual for Determining the Remaining Strength of Corroded Pipelines: A Supplement to B31, Code for Pressure Piping” (New York, NY: ASME). 15. P.H. Vieth, J.F. Kiefner, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipelines: A Supplement to B31, Code for Pressure Pipe” (Arlington, VA: PRCI,(6) 1989).

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16. P.H. Vieth, J.F. Kiefner, RSTRENG2 (DOS Version) User’s Manual and Software (Includes: L51688B, Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe) (Washington, DC: PRCI, 1993). 17. DNV Standard RP-F101 (latest revision), “Corroded Pipelines” (Oslo, Norway: Det Norske Veritas).

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Bibliography

Alvarez, C., and M.H. Al-Awwami. “Wet Crude Transport

Through a Complex Hilly Terrain Pipeline Network.” Society of Petroleum Engineers(7) 74th Annual Technical Conference and Exhibition, SPE 56463. (Richardson, TX: SPE, 1999).

ASTM D 1142 (latest revision). “Standard Test Method for

Water Vapor Content of Gaseous Fuels by Measurement of Dew-Point Temperature.” West Conshohocken, PA: ASTM.

Baldwin, R. 1999 Data Collected from Federal Energy

Regulatory Commission Bulletin Board Service (FERC BBS).

Beggs, H.D., and J.P. Brill. “A Study of Two-Phase Flow in

Inclined Pipes.” Journal of Petroleum Technology 5 (1973): p. 607.

Bendiksen, K.H., D. Malnes, R. Moe, and S. Nuland. “The

Dynamic Two-Fluid Model OLGA: Theory and Application,” SPE Production Engineering, May 1991, p. 171

Bich, N., and K. Szklarz. “Analysis of a Gas Field Corrosion

Failure at Crossfield.” Materials Performance 38, 7 (1999).

Braga, T.G., and R.G. Asperger. “Engineering

Consideration for Corrosion Monitoring of Gas Gathering Pipeline Systems.” CORROSION/87, paper no. 48. Houston, TX: NACE, 1987.

Byars, H.G. Corrosion Control in Petroleum Production.

TPC 5. Houston, TX: NACE, 1999. De Waard, C., U. Lotz, and D. Milliams. “Predictive Model

for CO2 Corrosion Engineering in Wet Natural Gas Pipelines.” CORROSION/91, paper no. 77. Houston, TX: NACE, 1991.

De Waard, C., and D. Milliams. “Carbonic Acid Corrosion of Steel.” Corrosion 31, 5 (1975).

Eckert, R., and B. Cookingham. “Field Use Proves Program

for Managing Internal Corrosion in Wet-Gas Systems.” Oil and Gas Journal 100, 3 (2002): p 48.

Fontana, M.G. Corrosion Engineering. New York, NY:

McGraw-Hill, 1986. French, E.C., and P.E. Eaton. “A Flush Mounted Probe for

Instantaneous Corrosion Measurements in Gas Transmission Lines.” CORROSION/76, paper no. 41. Houston, TX: NACE, 1976.

Gartland, P.O., and J.E. Salomonsen. “A Pipeline Integrity

Management Strategy Based on Multiphase Fluid Flow and Corrosion Modeling.” CORROSION/99, paper no. 622. Houston, TX: NACE, 1999.

Greenspan, L. Journal of Research of National Bureau of

Standards, 81A, 1, 89-96, U.S. Department of Commerce.(8) TIC: 241138 (1977).

Jones, H.G. “Gas Quality Control and Analysis.” AGA(9)

Operations Section Proceedings, held May 5-7, 1975 and May 19-21, 1975. Washington, DC: AGA, 1975.

Kern, D.M. “The Hydration of Carbon Dioxide.” Journal of

Chemical Education 37, 1 (1960): p. 14. Kearns, J.R., J.R. Scully, P.R. Roberge, D.L. Reichert, and

J.L. Dawson. Electrochemical Noise Measurement for Corrosion Applications. STP 1277. West Conshohocken, PA: ASTM,(10) 1996.

Kohl, A., and F. Riesenfeld. Gas Purification. Houston, TX:

Gulf Publishing Co., 1985.

___________________________ (6) Pipeline Research Council International, Inc. (PRCI), 1401 Wilson Blvd., Ste. 1101, Arlington, VA 22209. (7) Society of Petroleum Engineers (SPE), P.O. Box 833836, Richardson, TX 75083-3836. (8) U.S. Department of Commerce, 1401 Constitution Ave. NW, Washington, DC 20230. (9) American Gas Association (AGA), 400 N. Capitol St. NW, Washington, DC 20001. (10) ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959.

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Kennelley, K.J., R.H. Hausler, and D.C. Silverman, eds.

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Moghissi, O., L. Perry, B. Cookingham, and N. Sridhar.

“Internal Corrosion Direct Assessment of Gas Transmission Pipelines—Application.” CORROSION/2003, paper no. 204. Houston, TX: NACE, 2003.

NACE MR0175/ISO 15156 (latest revision). “Petroleum

and natural gas industries—Materials for use in H2S-containing environments in oil and gas production.” Houston, TX: NACE.

Nossen, J., R. Shea, and J. Rasmussen. “New

Developments in Flow Modeling and Field Data Verification.” 2nd North American Conference on Multiphase Technology, held June 21-23, 2000. Bedfordshire, UK: BHR Group Limited.(11)

Othmer, D.F, and R.E. Kirk. Concise Encyclopedia of

Chemical Technology. 4th ed. New York, NY: John Wiley & Sons, 1999.

Ostroff, A.G. Introduction to Oilfield Water Technology.

Houston, TX: NACE, 1979. Papavinasam, S., G. Shen, A.M. Doiron, and R.W. Revie.

“Prediction of Inhibitor Behavior in the Field from Data in the Laboratory.” CORROSION/2004, paper no. 622. Houston, TX: NACE, 2004.

Parkins, R.N. “Overview of Intergranular Stress Corrosion

Cracking Research Activities.” PR-232-9401. Arlington, VA: PRCI, 1994.

Pound, B. “Gap Analysis of the PRCI/GRI Research

Program on Internal Corrosion.” GRI Contract no. 6008. Report No. SF26363.000/AOTO/1198/BPO2. Arlington, VA: PRCI, 1998.

Richardson, D., and C. McGovern. “Integration of Fluid Flow

Effects Within a Risk-Based Pipeline Integrity

16

Management (PIM) Process.” In Multiphase Technology. New York, NY: ASME, 1998.

Shannon, D.W., N.J Olson, R.J. Robertus, D.D. Pierce, and

F.O. McBarron. “Effect of Water Chemistry on Internal Corrosion Rates in Offshore Natural Gas Pipelines.” PR-3-504. Arlington, VA: PRCI, 1988.

Shea, R., J. Rasmussen, P. Hedne, and D. Malnes.

“Holdup Predictions for Wet-Gas Pipelines Compared.” Oil and Gas Journal, May 19 (1997).

Sridhar, N., D. Dunn, A. Anderko, M. Lencka, and H. Schutt.

“Effects of Water and Gas Compositions on the Internal Corrosion of Gas Pipelines–Modeling and Experimental Studies.” Corrosion 57, 3 (2001).

Taitel, Y., and A.E. Dukler. “A Model for Predicting Flow

Regime Transitions in Horizontal and Near Horizontal Gas-Liquid Flow.” AIChE Journal 22, 1 (1976): p. 47.

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“Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards.” Part 192. Washington, DC: Office of the Federal Register, 1995.

U.S. Code of Federal Regulations (CFR) Title 49. “Part II,

Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipeline); Proposed Rule.” Part 192. Washington, DC: Office of the Federal Register, 2003.

van Bodegom, L., K. van Gelder, M.K.F. Paksa, and L. Van

Raam. “Effect of Glycol and Methanol on CO2 Corrosion of Carbon Steel.” CORROSION/87, paper no. 55. Houston, TX: NACE, 1987.

Videla, H. Manual of Biocorrosion. Boca Raton, FL: CRC

Press, 1996. Vieth, P., O.C. Moghissi, and L. Beavers. “Integrity-

Verification Methods to Support U.S. Efforts in Pipeline Safety.” Oil and Gas Journal 100, 51 (2002).

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Appendix A: Example DG-ICDA Application (Nonmandatory)

An example problem is outlined in this appendix. The example is not intended to provide any further requirements on ICDA performance. It is only to help illustrate the ICDA methodology. The pipeline of interest has an outer diameter of 760 mm (30 in.) and 8.33 mm (0.328 in.) wall thickness, for an inner

diameter of 745 mm (29.3 in.). The pipeline is oriented north to south, and the gas may flow in either direction, depending on demand. The process conditions are shown in Table A1.

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(11) BHR Group Limited, The Fluid Engineering Centre, Cranfield, Bedfordshire MK43 0AJ, UK.

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Table A1: Example Conditions

Flow S → N kNm3/h (million scf/d)

Flow N → S kNm3/h (million scf/d)

Pressure MPag (psig) Temperature °C (°F)

High 413 (370) 329 (295) 5.9 (850) 16 (61)

Average 313 (280) 246 (220) 4.8 (700) 16 (61)

Low 0 0 3.4 (500) 16 (61) Nm3/h = normal cubic meter per hour

The pressure and throughput are variable, but the maxima and minima are known. The lowest operating pressure, 3.4 MPag (500 psig), was used in calculations. The highest throughput in the south to north direction is 413 kNm3/h (370 million scf/d), and the highest throughput in the north to south direction is 329 kNm3/h (295 million scf/d). These values were selected because they represent the most extreme cases of possible liquid carryover; they yield the largest theoretical critical inclination angles for the pipeline. The temperature is a relatively constant ~16°C (289 K; or 61°F). As there were no crossovers or pressure regulators in the line, two regions were defined, based on flow direction. Region 1 was defined for the south to north flow direction, Region 2 for north to south. Collected data used in the example calculations of critical inclination angle are pipe inner diameter (dID); lowest operating pressure (P); average temperature (T); maximum standard flow rate; liquid density (ρL) (default 1 g/cm3 may be changed); and molecular weight (MW) of gas (or assume methane 16 g/g-mol). Constants are gravity, g = 9.81 m/s2

(32.17 ft/s2); ideal universal gas constant, R = 8.314 Pa - m3/g-mol/K (1.987 BTU/lb-mol/R); and compressibility factor, Z = 0.83.

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Find gas density (ρg) as shown in Equation (A1):

TRZMWPρg ××

×= (A1)

K 289mol/K)/gmPa(8.314 0.83

molg/g16 MPag0.101325)(3.4gρ 3 ×−•×

−×+=

3g g/cm0.028ρ =

Next, calculate the superficial velocity of gas flow in the pipe. If flow rate is in standard (STP) units, use the ideal gas law (PV = nRT) to convert to operating pressure (OP) flow rate, or flow rate for the specific conditions as shown in Equation (A2).

By the ideal gas law, ZnRT

PV (operating conditions) =

STP

STPSTP

nRT

VP (standard temperature and pressure). n and R

drop out, and flow rate may be considered proportional to volume, therefore, we can rearrange to obtain the operating (OP) flow rate from the provided maximum standard (STP) flow rate, as shown in Equation (A2):

STP

STP

TP

ZPTRateFlowSTPRateFlowOP

×××

= (A2)

K273MPa0.101325)(3.4

MPa0.1013250.83K289h)/m10(413RateFlowOP

33

×+××××

=

h/m1010.5RateFlowOP 33×=

Where: Metric standard conditions are PSTP = 0.101325 MPa and TSTP = 273 K. Next, calculate superficial velocity, Vg, as shown in Equation (A3):

Area

RateFlowOPVg = (A3)

[ ]4)/(dπRateFlowOP

V2ID

g×

=

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][ )/4m][0.745(πs)(1h/3,600/hm1010.5

V2

33

g×

××=

sm/6.7Vg =

For the same input values using the Van daar Waal’s equation (with a [methane] = 2.25 L2 atm/mol2 and b [methane] = 0.0428 L/mol), a Vg value of 5.9 m/s is obtained.11,12 Solve Equation (A4) to find the critical inclination angle, θ, as explained in Section 4.2.2:

1.0912

g

gl

g

IDg

V

ρρρ

0.675arcsinθ⎟⎟

⎠

⎞

××⎜

⎜⎝

⎛

−= (A4)

1.091

m 0.7452m/s 9.81

2m/s) (6.73g/cm0.028 3g/cm 1

3g/cm0.028 0.675arcsinθ ⎟

⎟

⎠

⎞

××⎜

⎜

⎝

⎛

−=

=θ 6o

For 413 kNm3/h (370 million scf/d), the critical inclination angle is 6 degrees; the critical inclination angle for the south-to-north direction. For the north-to-south direction,

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329 kNm3/h (295 million scf/d), the critical inclination angle is 4 degrees. The next step is to produce an inclination graph and superimpose critical inclination angles over the inclination profile so the sites can be identified for direct examination/inspection. The elevation profile was determined using a static global positioning system (GPS) unit for position and ground elevation, and a pipe locator for depth-of-cover. The inclination profile for the pipe was calculated from these data. For each segment, the inclination angle may be found and plotted as in Equation (A5):

⎟⎟⎠

⎞⎜⎜⎝

⎛(distance) ∆

)(elevation ∆arcsin=θ (A5)

The elevation profile and inclination profile are shown together in Figure A1, in which the south input is 0 km (0 mile). Critical inclination angles for each flow direction are also shown. The Region 1 (south-to-north flow) and Region 2 (north-to-south flow) inclinations of interest are expanded in Figures A2 and A3, respectively, to show inclination angles greater than the critical inclination angle for each region. Results of a theoretical inspection are shown in Table A2.

OVERVIEW - Elevation and Inclination vs. Stationing

-40.0

-20.0

0.0

20.0

40.0

60.0

80.0

100.0

0 5 10 15 20 25Distance, km (mi)

Incl

inat

ion

, deg

rees

-100

-50

0

50

100

150

200

Ele

vati

on

, m (

ft)

Inclination (S->N) Critical Angle (S->N) degrees Critical Angle (N->S) degrees Elevation

Moving North

Moving South

Elevation

Inclination

(3) (6.2) (16)(12)(9.3)(0) (-328)

(-160)

(160)

(0)

(328)

(492)

(656)

Figure A1: Example inclination and elevation profiles, with critical inclination angles. Screen capture of spreadsheet. (1 ft = 0.3048 m, 1 mile = 1.609 km)

NACE International

-2006

SP0206

Inspection Region Subregion Stationing, Inclination Angle, Internal CorrosionNumber km (mi) degrees Present?

1 I 0.08 (0.05) 9 Yes2 I 0.88 (0.547) 16 Yes3 I 1.03 (0.640) 9 No4 I 1.22 (0.758) 8 No5 I 2.89 (1.80) 7 No6 I 1 0.84 (0.52) 5 Yes7 I 1 0.66 (0.41) 3 No8 I 1 0.27 (0.17) 2 No

9 II 28.839 (17.92) 7 Yes10 II 28.035 (17.42) 14 Yes11 II 26.63 (16.55) 4 No12 II 25.798 (16.03) 6 No13 II 24.72 (15.36) 18 No

Table A2: Example—Inspection Results

For Region 1, the uphill inclination data are shown in Figure A2, with the critical inclination angle for south to north represented by the dashed line at 6 degrees. In this example, corrosion was found at the first two inclines examined (Digs #1 and #2); therefore, the search for corrosion continued downstream. No additional corrosion was found downstream (Digs #3, #4, and #5). As a result, two subregions were defined: Subregion 0 from 0 km to 0.08 km (0 to 0.05 mile) (i.e., from 0 km to Dig #1), and Subregion 1 from 0.08 km to 0.88 km (0.05 to 0.55 mile) (i.e., from Dig #1 to Dig #2). There were no additional

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upstream sites in Subregion 0; however, there were additional potential liquid holdup locations in Subregion 1. The next highest inclination in Subregion 1 was 5 degrees, at 0.84 km (0.52 mile) (i.e., Dig #6). Corrosion was found at this location. The search for internal corrosion continued upstream in the subregion. The next highest inclination upstream was 3 degrees, at 0.66 km (0.41 mile) (i.e., Dig #7); no corrosion was found. No corrosion was found at the last site upstream in the subregion, 2 degrees at 0.274 km (0.17 mile) (i.e., Dig #8). The detailed examination process was complete for Region 1.

-20.0

0.0

20.0

40.0

60.0

80.0

100.0

0.0 1.0 2.0 3.0 4.0 5.0 6.0

Distance, km (mi)

Incl

inat

ion

, deg

rees

-100

-50

0

50

100

150

200

Ele

vati

on

, m (

ft)

Inclination (S->N) Critical Angle (S->N) degrees Critical Angle (N->S) degrees Elevation

Moving North

1

7

64

32

8 5

(660)

(490)

(330)

(160)

(0)

(-160)

(-330)(3.1)(0.6) (1.2)(0) (1.9) (2.5) (3.7)

Figure A2: Example inclination profile, gas flowing south to north (first 6.4 km [4 miles]). Elevation is shown for reference. Screen capture of spreadsheet. (1 ft = 0.3048 m, 1 mile = 1.609 km)

The numbers on Figure A2 indicate the order of excavation.

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SP0206-2006

The uphill inclination data for Region 2 are shown in Figure A3, with the critical inclination angle for north to south represented by the solid line at -4 degrees. Internal corrosion was found at both of the first sites inspected, 28.839 km (17.92 miles) and 28.035 km (17.42 miles) (i.e., Digs #9 and #10). Therefore, the search for internal corrosion continued downstream. No corrosion was found at the next two sites examined (Digs #11 and #12), nor at the validation site at 24.72 km (15.36 miles) (i.e., Dig #13). Subregions were defined as follows: Subregion 0 between 29.3 km (18.2 miles) and 28.839 km (17.92 miles), and Subregion 1 between 28.839 km (17.92 miles) and 28.035 km (17.42 miles). There were no additional potential liquid

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holdup locations in either region; therefore, the detailed examination process was complete for Region 2. Note that an adjacent inclination must be associated with a unique low point to be considered a separate liquid holdup location. The benefit of the DG-ICDA approach is that an assessment may be performed on a pipe segment for which it is not practical to perform ILI. Examination of a limited portion of the line provides information about the remaining length. Internal corrosion is identified but is limited to a few locations. Repairs can be made, possible process problems investigated, and integrity is similarly assured.

Figure A3: Example inclination profile, gas flowing north to south (first 6.2 km [3.9 miles]). Elevation is shown for reference. Screen capture of spreadsheet. (1 ft = 0.3048 m, 1 mile = 1.609 km)

-120.0

-100.0

-80.0

-60.0

-40.0

-20.0

0.0

20.0

24.025.026.027.028.029.0

Incl

inat

ion

, deg

rees

-100

-50

0

50

100

150

200

Ele

vati

on

, m (

ft)

Inclination (S->N) Critical Angle (S->N) Critical Angle (N->S) Elevation

Distance, km (mi)

Moving South9 121110 13

(660)

(490)

(330)

(160)

(0)

(-160)

(-330)(18.0) (17.4) (16.8) (16.2) (15.5) (14.9)

NACE International

SP0206-2006

NACE Inte

________________________________________________________________________

Appendix B: Example Region Definition (Nonmandatory)

Figure B1 is an example of DG-ICDA region definitions for a given pipeline. All historic outlets and inlets are shown (Location A, Location B, end, and beginning of the line). There was suspected backflow at the outlet of Location A between 1978 and 1988, so this location has also been used in the region definitions. From this information, the pipeline operator defined three distinct DG-ICDA regions.

rnational

The example shown in Appendix A would correspond with the pipe length contained in Region 3, between location B and the receiver; however, only flow in the north-to-south direction (designated Region 2 in Appendix A) is shown in Figure B1.

Years: 1993 to 2002

NORTH Launcher Location A

19.3 km

(Output Not

Active)

Location B 29 km

(Input Not

Active)

SOUTH Receiver

5 MPag (725 psig), Low 7 MPag (1,015 psig), High Max Flow = 329 kNm3/h (295 million scf/d)

3.45 MPag (500 psig), Low, 5.9 MPag (850 psig), High Max Flow = 329 kNm3/h (295 million scf/d)

Years: 1988 to 1993

5.9 MPag (850 psig)

No Gas Flow

X X

Years: 1978 to 1988 (Pipeline Installed in 1978)

3.45 MPag (500 psig), Low, 5.9 MPag, (850 psig), High Max Flow = 303 kNm3/h (271.5 million scf/d)

3.45 MPag (500 psig), Low, 5.9 MPag, (850 psig), High Max Flow = 303 kNm3/h (271.5 million scf/d)

3.45 MPag (500 psig), Low, 5.9 MPag (850 psig), High Max Flow = 329 kNm3/h

Launcher Receiver

Receiver

Launcher

Location A

19.3 km

(Output Not

Active)

Location B

29 km

(Input Not

Active)

Max Flow = 47.3 kNm3/h (42.4 million scf/d)

Location A

19.3 km

Location B 29 km

Max Flow = 26.5 kNm3/h (23.7 million scf/d)

5.9 MPag (850 psig)

No Gas Flow

5.9 MPag (850 psig)

No Gas Flow

3.45 MPag (500 psig), Low, 5.9 MPag (850 psig), High Max Flow = 329 kNm3/h (295 million scf/d)

REGION 1 REGION 2 REGION 3

Figure B1: Illustration of ICDA Region Definitions

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